Since the advent of hydraulic fracturing, significant efforts have been made to discover what is actually occurring when fluids are injected into a target reservoir. Various technologies are used to determine the dimensions, orientation and conductivity of a hydraulically induced fracture. Direct and near-wellbore techniques use temperature logs and radioactive tracers to obtain data about fracture height and proppant placement. Beyond direct measurements made within the wellbore, tiltmeter and microseismic data may be used to monitor the orientation and dimensions of hydraulic fractures. These in-situ reservoir studies, away from the wellbore, have the potential to image the areal extent of the fracture network as it develops through time. New technologies used to estimate stimulation effectiveness include fiber-optics-based distributed temperature and acoustic sensing tools. Each of these analysis tools has its own set of strengths and weaknesses and requires its own assumptions to provide valid and confident results.
A combined analysis using both microseismic fracture mapping and fiber-optic distributed temperature sensing (DTS) was conducted for a single well completed in the Barnett shale.